nigeria power sector program long-term …

NIGERIA POWER SECTOR PROGRAM

LONG-TERM PLANNING ASSESSMENT

April 2019

DISCLAIMER:

This publication was prepared for review by the United States Agency for International Development. It was

prepared by Deloitte Consulting LLP. The author’s views expressed in this publication do not necessarily reflect

the views of the United States Agency for International Development or the United States Government.

LONG-TERM PLANNING ASSESSMENT ii

NIGERIA POWER SECTOR PROGRAM

(NPSP)

LONG-TERM PLANNING ASSESSMENT IDIQ Contract No. 720-674-18-D-00003 Power Africa Extension (PAE)

Task Order No. 720-674-18-F-00003 Nigeria Power Sector Program (NPSP)

USAID | Southern Africa

Contracting Officer’s Representative: John Garrison

Contributors: Yousef Majzoub

Reviewers: Colin McCollester and Grayson Heffner

Submitted:

ACKNOWLEDGEMENT:

This document was produced for review by the United States Agency for International Development. It was

prepared under Task Order No. 01: The Nigeria Power Sector Reform Program (the “Task Order”) of the

Power Africa Indefinite Delivery, Indefinite Quantity (“IDIQ”) Contract No. 720-674-18-D-00003 implemented

by Deloitte Consulting LLP.

LONG-TERM PLANNING ASSESSMENT iii

ACRONYMS

Acronym Definition

DISCO Distribution Company

EPSRA Electric Power Sector Reform Act

FGN Federal Government of Nigeria

GAR Generation Adequacy Report

GENCO Generation Company

JICA Japan International Cooperation Agency

MYTO Multi-Year Tariff Order

NARUC National Association of Regulatory Utility Commissioners

NBET Nigerian Bulk Electricity Trading PLC

NERC Nigerian Electricity Regulatory Commission

PPA Power Purchase Agreement

RAM Review, Approval, and Monitoring

TCN Transmission Company of Nigeria

TEP Transmission Expansion Plan

LONG-TERM PLANNING ASSESSMENT iv

TABLE OF CONTENTS

EXECUTIVE SUMMARY ................................................................................................................................. 1

PURPOSE OF THE ASSESSMENT ....................................................................................................................... 1

CURRENT STATE OF LONG-TERM PLANNING ......................................................................................... 1

CONSEQUENCES ARISING FROM LACK OF LONG-TERM PLANNING ........................................... 1

1. INTRODUCTION ................................................................................................................................... 3

1.1 BACKGROUND AND CONTEXT........................................................................................................... 3

1.2 PURPOSE AND STRUCTURE .................................................................................................................... 3

2. SYSTEM PLANNING ............................................................................................................................... 5

2.1 OVERVIEW ...................................................................................................................................................... 5

2.2 KEY CHALLENGES AND IMPACTS ......................................................................................................... 7

3. LOAD DEMAND FORECASTING ................................................................................................... 12

3.1 OVERVIEW .................................................................................................................................................... 12

3.2 KEY CHALLENGES AND IMPACTS ....................................................................................................... 14

4. DISTRIBUTION EXPANSION PLANNING ................................................................................... 16

4.1 OVERVIEW .................................................................................................................................................... 16


5. TRANSMISSION EXPANSION PLANNING .................................................................................. 20

5.1 OVERVIEW .................................................................................................................................................... 20


6. GENERATION EXPANSION PLANNING ..................................................................................... 24

6.1 OVERVIEW .................................................................................................................................................... 24


7. CONCLUSION ...................................................................................................................................... 29

LONG-TERM PLANNING ASSESSMENT v

LIST OF TABLES

TABLE 1: KEY TAKEAWAYS......................................................................................................................................... 2 TABLE 2: PLANNING HORIZONS ............................................................................................................................. 8 TABLE 3: CURRENT TCN FORECAST FACTORS VS. GRID CODE FORECAST FACTORS ................. 13 TABLE 4: CURRENT DISCO FORECAST APPROACH ...................................................................................... 14 TABLE 5: DISCO EXPANSION PLAN VS. REQUIRED DISTRIBUTION CODE ATTRIBUTES ............... 17 TABLE 6: DISTRIBUTION CODE (PART 2) SECTIONS GOVERNING DISCO PLANNING .................. 18 TABLE 7: SYSTEM ADEQUACY REPORTS CURRENT METHODOLOGY OVERVIEW ........................... 21

LIST OF FIGURES

FIGURE 1: NIGERIA POWER SYSTEM PLANNING OVERVIEW ....................................................................... 6 FIGURE 2: CURRENT SYSTEM PLANNING STATUS AS OF NOVEMBER 2018 ........................................... 7 FIGURE 3: APPROXIMATION OF CURRENT IDLE INFRASTRUCTURE CAPACITY .............................. 10 FIGURE 4: LOAD FORECAST PROCESS GAPS ..................................................................................................... 12 FIGURE 5: DISTRIBUTION EXPANSION PLAN MARKET RULES PROCESS ............................................... 16 FIGURE 6: TRANSMISSION EXPANSION PLAN PROCESS .............................................................................. 20 FIGURE 7: TRANSMISSION EXPANSION PLAN (FICHTNER) OVERVIEW ................................................. 22 FIGURE 8: TRANSMISSION EXPANSION PLAN GRID CODE PROCESS .................................................... 23 FIGURE 9: EXISTING AND PROPOSED GAS TRANSMISSION INFRASTRUCTURE ................................ 25 FIGURE 10: GENERATION EXPANSION PLAN PROCESS ............................................................................... 26

LONG-TERM PLANNING ASSESSMENT 1

EXECUTIVE SUMMARY

PURPOSE OF THE ASSESSMENT

The Long-term Planning Assessment seeks to identify current shortcomings of Nigeria’s long-term energy

system planning mechanisms and suggest potential improvements. Long-term energy system planning

mechanisms can ensure that future load demand is reliably supplied by generating units at the lowest

possible cost to consumers. Long-term planning also ensures that waste and idle capacity, in generation,

transmission, and distribution, is avoided by aligning interests of different stakeholders in the value chain.

CURRENT STATE OF LONG-TERM PLANNING

The Nigerian Electricity Regulatory Commission (NERC) has recently called for the submission of

transmission and distribution expansion plans to enhance overall power system planning. Until now, the

Nigerian power system has operated without the benefit of any type of industry-wide accepted plan. Each

part of the power value chain has been planned in relative isolation, with investments and expansions

carried out on an ad hoc basis without consideration for other parts of the value chain. Power projects

are accepted on an unsolicited basis from many developers, leading to an incoherent system with many

infrastructure gaps and bottlenecks. The Nigerian power system has generation capacities that are severely

underutilized and will only become dispatchable when transmission and distribution bottlenecks are

relieved to meet incident load growth. Despite these bottlenecks, there are also areas where transmission

and distribution infrastructures are underutilized. In many cases, mismatches at the interface between the

transmission and distribution systems, cause either distribution capacity or transmission capacity to be

underutilized. In addition to planning issues affecting electricity infrastructure, the lack of coordination in

developing generation investments has resulted in non-operational generating units due to gas

transmission constraints (e.g., pipeline size).

CONSEQUENCES ARISING FROM LACK OF LONG-TERM PLANNING

The lack of planning coordination among the various stakeholders of the power value chain has resulted

in an inefficient allocation of resources in network infrastructure development. Consequently, the

mismatch of capacity along the power sector value chain has resulted in bottlenecks and surplus capacities

ultimately limiting the average energy delivered to end users to approximately 4,000 MW1. This has an

adverse effect on total system cost, since underutilized/surplus capacities may be considered as part of

the asset base during tariff determination. In order to ensure the reliability of the power grid system in

the long-term, Nigeria’s long-term energy system planning mechanism must be strengthened by formalizing

a planning framework, engaging stakeholders by ensuring the provision of economic incentives, and

improving the technical capacity of stakeholders to carry out planning activities. See Table 1 below for a

summary of the different challenges, their causes, potential interventions to address them, and expected

outcomes.

1 NERC Quarterly Reports


Table 1: Key Takeaways

Problem Causes Actions for Change Outputs

Misallocation of power

sector financial and

infrastructure resources

No integrated system planning mechanism in

place

NERC to formalize a planning framework2 and

effectively communicate to each stakeholder

their scope of responsibilities and interactions

Optimal allocation of

power sector

infrastructure

investments to reliably

meet future load

requirements at the

lowest possible cost

Misaligned planning horizons across

expansion plans and system adequacy reports

NERC to implement existing regulations, align

planning horizons, and develop new guidelines

and a communication mechanism to facilitate an

integrated planning mechanism

Inadequate investment

monitoring and planning

inputs

Power value chain stakeholders lack the

capacity (i.e., technical, software, hardware,

data collection mechanism, etc.) to effectively

carryout planning activities in line with

current rules and leading practices

NERC to develop load forecasting and expansion

plan templates to streamline the review process

and ensure uniformity

More robust and

accurate long-term

expansion plans and the

reduced risk of

misaligned infrastructure

investments

Power value chain stakeholders to improve their

technical capacity to comply with designated

planning responsibilities

Implementation

uncertainty of expansion

plans

Lack of stakeholder incentive arising from

sector liquidity issues, partly attributed to the

recovery costs that must be paid by

consumers for idle/surplus capacities

Provide economic incentives for stakeholders

(e.g., Big Customers, distribution companies, etc.)

to engage in planning activities

Increased stakeholder

buy-in and the availability

of capital expenditure

funds through the Multi-

Year Tariff Order

framework

NERC to develop processes to align planning

requirements with the capital cost allowance in

the Multi-Year Tariff Order framework

2 A USAID-funded consultant under the National Association of Regulatory Utility Commissioners (NARUC) assistance to NERC has developed a system planning

process flow chart.


1. INTRODUCTION

1.1 BACKGROUND AND CONTEXT

The Federal Government of Nigeria (FGN) has in place regulations governing the objectives and

procedure for developing power system plans by certain stakeholders across the power sector value

chain. Most of the regulations pertaining to the development of system plans are found in the Nigerian

Electric Power Sector Reform Act 2005 (EPSRA), Market Rules, Grid Code, Distribution Code, and the

Multi-Year Tariff Order (MYTO).

As mandated by EPSRA and described in the Market Rules (Part 5 – Contracts, Generation Adequacy and

Power Procurement during the Transitional Stage), NERC is responsible for reviewing plans submitted by

the operators of the power system to ensure integrated power system development within Nigeria.

However, to date, no power system planning and grid expansion has been fully implemented. Each part of

the power value chain has been planned in isolation, without consideration for the load demand and other

parts of the value chain. In other words, the Nigerian power system has developed without the benefit of

any type of overarching or integrated planning framework.

The lack of planning coordination among the various stakeholders of the power sector value chain has

produced inefficiencies and mismatches in network infrastructure development. The most notable

consequence is capacity bottlenecks limiting the average energy delivered to end users to approximately

4,000 MW3 compared to an available generation capacity of approximately 7,500 MW4. In addition, the

Nigerian power system has surplus capacities that are currently underutilized and will only become

operational when bottlenecks are relieved to meet incident load growth. The sector lacks a logical

framework to prioritize infrastructure investments that will clear bottlenecks and efficiently get over to

where it is ready to be used. Currently surplus capacities are not immediately utilized and are partly

responsible for the liquidity challenges faced by the Nigerian power system. The complete lack of

coordinated planning in the sector has created difficulties in identifying bottlenecks because agencies

planning in silos necessarily tend to have a limited view of the sector. In recent years, this issue has led to

finger pointing and a severe lack of trust among industry participants.

1.2 PURPOSE AND STRUCTURE

The purpose of this sector planning assessment is to explore the state of Nigeria’s power sector planning

apparatus and identify opportunities for improvement. This assessment builds on the USAID funded

technical assistance project by the National Association of Regulatory Utility Commissioners (NARUC)

to develop NERC’s capacity to evaluate system planning, hereinafter referred to as NARUC Technical

Assistance Project (2018).5 The assessment relies on historical references and completed planning

documents.6

The assessment comprises of five parts, providing an overview of the key stakeholders, current

mechanisms, key challenges and impacts, and potential improvements in the following areas:

3 NERC Quarterly Reports 4 NARUC Technical Assistance Project (2018) 5 Project Title: Technical Assistance on Developing the Nigerian Electricity Regulatory Commission’s Capacity to

Evaluate System Planning 6 Note: The Japanese International Cooperation Agency (JICA) is currently conducting a comprehensive Power

Sector Master Plan Study in Nigeria which is expected to include a power demand forecast, a least-cost plan, a

generation plan considering energy supply and best mix, and a transmission development plan based on the

generation plan (https://www.jica.go.jp/nigeria/english/office/topics/150904.html). According to NPSP Meeting Notes

with JICA (September 3, 2018), the JICA Master Plan incorporates the Fichtner study discussed below.


1. System Planning: facilitates the coordination, review, and integration of planning activities

across multiple stakeholders within the power sector.

2. Load Demand Forecasting: informs infrastructure investment decisions by improving load

demand forecasts and coordination among power sector stakeholders.

3. Distribution Expansion Planning: aligns the allocation of distribution infrastructure

investments with load demand growth and transmission infrastructure investments.

4. Transmission Expansion Planning: aligns the allocation of transmission infrastructure

investments with load demand growth, distribution infrastructure investments, and generation

resources.

5. Generation Expansion Planning: aligns the allocation of generation infrastructure investments

with energy resource availability and plans, load demand growth, and transmission plans.

This assessment will rely on the Market Rules, along with the Grid Code and Distribution Code, in

reviewing the current mechanisms in place and will only briefly discuss interim provisions in place as they

are subject to intermittent change.7

7 Note: NERC has in place interim provisions that override the load forecast and generation adequacy requirements

of the Market Rules; please refer to Market Rules 21.3 Interim Provisions and the interim provision by NERC titled

Regulations for the Procurement of Generation Capacity 2014.


2. SYSTEM PLANNING

2.1 OVERVIEW

The Nigerian power system has developed without the benefit of an overarching or integrated planning

framework, resulting in uncoordinated investments and expansions across the value chain. This is

particularly evident in generation, where unsolicited projects are often taken forward without

consideration of grid capacity or stability. The current model of unsolicited power projects leads to a lack

of control of system design making bottlenecks and underutilized system capacity a likelihood. As this

report shows, it is difficult to adapt to rapidly expanding load growth in a cost-efficient manner without

sector planning and coordination.

The key challenges hindering Nigeria’s system planning mechanism include, but not limited to, the lack of

leadership, an uncoordinated planning framework, power sector stakeholder capacity challenges, and the

lack of stakeholder incentives to commit to long term planning. This provides NPSP with the opportunity

to support the formalization of a planning framework and communication guidelines, in addition to

providing capacity development support and communicating the importance of planning to increase

stakeholder involvement.

Early efforts towards coordinated development of the sector include:

• Electric Power Sector Reform Act 2005 (EPSRA) – Assigns the authority to NERC to set

and enforce standards in the Nigerian power sector, inclusive to assigning NERC with certain

functions to perform in the Nigerian power sector (Part III – Establishment, Functions and Powers

of the Nigerian Electricity Regulatory Commission).

• Market Rules – Establishes an approach to system planning in the Nigerian power system and

allocates planning responsibilities to distribution companies (DISCOs) and the Transmission

Company of Nigeria (TCN). The Market Rules version dated December 2014 was consulted for

this assessment.

• Grid Code – Specifies detailed steps and criteria for planning, particularly for load demand

forecasting, system adequacy studies, and transmission expansion plans. Grid Code Version 03

was consulted for this assessment (August 2018).

• Distribution Code – Outlines requirements for the approach and items DISCOs need to

consider when formulating their distribution expansion plans and load demand forecasts.

Distribution Code Version 02 was consulted for this assessment.

• Multi-Year Tariff Order (MYTO) – Establishes the wholesale and retail tariff over a 15-year

period, subject to periodic reviews, for the Nigerian electricity market. The objective of the

original order (July 2008) is to ensure adequate recovery of investments in the generation,

transmission, and distribution of electricity in Nigeria. The MYTO authorizes NERC with the

responsibility to ensure an adequate recovery of system costs through an efficient tariff

determination while reviewing and approving system plans.

According to these laws and regulations in place by FGN, the system planning process includes multiple

stages involving creation, approval, implementation, and monitoring. The main planning responsibilities

assigned to each stakeholder may be briefly summarized as follows: (1) DISCOs are responsible for

preparing load forecasts and distribution expansion plans; (2) TCN is responsible for preparing national

load forecasts, generation adequacy reports, transmission expansion plans, and generation expansion

plans; and (3) NERC is responsible for coordinating, reviewing, and approving all planning outputs from

stakeholders, in addition to conducting a tariff affordability test to estimate the impact of new power


procurements on tariffs.8 Furthermore, NERC engages in monitoring activities to ensure that the

implementation of investments by power sector stakeholders is aligned to the approved plans and is a

function mandated by Part III of the EPSRA.9 A brief overview of this approach is detailed in Figure 1

below.

Figure 110: Nigeria Power System Planning Overview11

As illustrated in Figure 1 above, the key actors in the Nigerian power sector with responsibilities in

planning include NERC, TCN, DISCOs, and Nigerian Bulk Electricity Trading (NBET). Generation

companies (GENCOs) are notably absent, but they are required to provide adequate data to the System

Operator upon request for planning purposes. The Market Rules, along with other FGN laws, do not

mandate GENCOs, gas suppliers, or any other agencies (e.g., the Nigerian Meteorological Agency, the

Nigerian Hydrological Services Agency, etc.) with any forecasting or planning activities.

Despite the existence of the defined process above, in practice, the planning process is not consistent

with current laws and regulations, and global leading practices. The defined process in the figure above

was derived by consolidating the planning guidelines stipulated in the Market Rules, Grid Code, and

Distribution Code. The current laws and regulations do not go as far as clearly defining the interactions

between power sector stakeholders (e.g., how is the planning process initiated and how are stakeholders

informed) and does not align planning horizons for the stakeholders which casts ambiguity on the

frequency of the planning process, refer to the Planning Challenge below.

8 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the

Nigerian power sector. 9 EPSRA Part III - Establishment, Functions and Powers of the Nigerian Electricity Regulatory Commission 10 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,

Grid Code Chapter 2 - Planning, and Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures 11 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the

Nigerian power sector. Figure 1 does not capture all the activities from the Market Rules, Grid Code, and

Distribution Code. Also, the figure does not capture all the interactions between the activities and stakeholders (e.g.,

System Operator involved also in TEP activity). Refer to the relevant subsections below for a more detailed process

description for each stakeholder.


In 2018 NERC called for the existing transmission expansion plan from the System Operator (a division

of TCN) and required DISCOs to complete a five-year distribution expansion plan template for review

and approval to ensure an integrated system planning effort.12 An overview of the ongoing planning process

is illustrated in Figure 2 below.

Figure 213: Current System Planning Status as of November 201814

As depicted by the figure above, the ongoing planning process fails to integrate key planning activities such

as DISCO load forecasts between the relevant stakeholders. The significance of not effectively integrating

key planning activities between stakeholders will be further discussed below.

It is important to note the presence of a system planning process flow chart developed by the NARUC

Technical Assistance Project (2018) consultant and NERC. According to the final project report of

NARUC Technical Assistance Project (2018), the system planning process flow chart begins with NERC

requesting load demand forecasts and generation forecasts from load participants and generating

companies, respectively, and ends with the Power Procurement Plan from NBET. The developed flow

diagram accounts for activities such as generation forecasts, generation expansion plans, and stakeholder

engagement. This flow chart is expected to act as a guide for future reviews of system plans within the

Nigerian power sector.

2.2 KEY CHALLENGES AND IMPACTS

2.2.1 Planning Challenge

FGN rules and regulations do not lay out a clear process or communication mechanism between power

sector stakeholders for system planning in line with an effective integrated sector master planning

framework.

This causes confusion over the scope of responsibilities, interactions with other stakeholders, where to

send the output of planning activities, and how to implement respective plans. The lack of clear guidelines

or procedures have consequences in three key areas: (1) communication and document submission; (2)

accounting for future domestic load and contracted power export requirements; and (3) implementing an

effective resource plan.

12 NARUC Technical Assistance Project (2018). 13 Ibid. 14 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the

Nigerian power sector. Furthermore, Fichtner was consulted for the preparation of the most current TEP.


Another contributing factor may be the misaligned planning horizons across the Nigerian power sector

value chain, refer to Table 2 below.

Table 2: Planning horizons

Document Planning Horizon Reference

Distribution

Expansion Plan /

Load Demand

Forecast

5 years

Distribution Code (Part 2) 2.1.3 Distribution Planning

Responsibility and Distribution Code (Part 2) 2.3.1 Load

Forecast

Transmission

Expansion Plan /

Load Demand

Forecast

20 years Grid Code 6.2.1 Long-term Demand Forecast and Grid

Code 7.2.7 Long-term Expansion Plan

TCN System

Adequacy

Reports

(Generation,

Transmission,

etc.) /

Load Demand

Forecast

10 years

Market Rules 21.1.1 Annual Load Projections Report and

Market Rules 21.2.2 Generation Adequacy Report; TCN

System Adequacy Reports (2017)

2.2.2 NERC Capacity Challenge

Despite the guidelines in place regarding system planning, NERC suffers technical and resource constraints

that inhibit the achievement of system planning objectives. NERC does not have adequate technical

capacity to perform tasks such as effectively reviewing system plans and/or effectively performing a tariff

affordability test. Furthermore, it has insufficient resources to effectively monitor all procurements or

investments in the power sector. However, it is important to note that NARUC is providing technical

assistance to NERC for the development of a Review, Approval, and Monitoring Guide for reviewing,

approving, and monitoring system development plans. The technical assistance has provided NERC with

the following two mechanisms: (1) a framework for monitoring procurement and investment in the power

sector; and (2) review and approval procedures and templates for system planning.15

15 NARUC Technical Assistance Project (2018).

NPSP can support NERC and TCN in (1) implementing an appropriate energy

resource planning framework; (2) organizing an industry workshop with all system

participants to effectively communicate the steps towards effective planning; and (3)

developing the necessary regulatory guidelines required to support an energy

resource planning framework. In addition, NPSP can develop a communication

mechanism between power sector stakeholders and train stakeholder personnel on

the requirements and guidelines for interacting with other entities in the power

sector.


2.2.3 Sector Liquidity and Stakeholder Incentive Challenge

Stakeholders of the power value chain lack a compelling driver to implement the current guidelines set in

place by FGN regulations and effectively engage in long-term planning activities. The lack of a cost-

reflective tariff, active Power Purchase Agreements (PPAs)/ Gas Supply Agreements, financing options,

and reliable payments may hinder the required efforts from stakeholders to implement long-term

expansion plans or even maintain their existing capacity. For example, DISCOs may be reluctant to

develop and adhere to a Performance Improvement Plan if the commission is unable to commit to tariff

revisions. It is worth noting that investments in the power sector rely on tariffs for assurances and cost

recovery.

2.2.4 Stakeholder Capacity Challenge

In the current system there are numerous instances of planning and study methodologies failing to comply

with requirements mandated by FGN laws and regulations. An effective system planning mechanism relies

on accurate and comprehensive inputs from other power sector entities, such as accurate forecasts of

load demand. It is crucial that any analysis carried out, which generates inputs for subsequent activities, is

compliant with FGN rules and leading practices to ensure accuracy and, most importantly, consistency

across released reports, especially with respect to load forecasts and system studies. A major contributing

factor to this discrepancy is likely the capacity gap facing power sector stakeholders with planning-related

responsibilities, including TCN, DISCOs, and large consumers (e.g., industrial companies).

2.2.5 Power System Optimization Impact

A lack of adherence to a system planning approach has led to inadequate allocation of power sector

infrastructure resources (e.g., generating units, transmission lines). The sector needs an integrated plan to

maximize infrastructure investments by identifying priority projects and geographic locations. The current

model of unsolicited power projects leads to a lack of control of system design making it difficult to adapt

to serve future load growth. There is no shared and consistent load projection estimate among the key

NPSP can provide technical assistance to NERC in: (1) acquiring and implementing

software tools for use in long term planning; (2) updating and operationalizing the

Review, Approval, and Monitoring guide provided through the NARUC Technical

Assistance Project (2018), and (3) implementing a NERC capability development

program.

NPSP can support the (1) communication of the importance of accurate data on the

power sector asset base for tariff determination; (2) audit and verification of power

sector infrastructure assets; and the (3) implementation of an asset register to ensure

the presence of accurate asset data for the process of tariff determination. In

addition, NPSP will work with NERC to identify and address governance issues.

To address the Stakeholder Capacity Challenge, NPSP can support the following: (1)

development of forecasting and expansion plan templates; (2) formation of

operational plans to address capacity gaps (e.g., hardware, software, etc.) afflicting

stakeholders; and (3) implementation of stakeholder development programs.


actors in the Nigerian power sector. In order for the system to work, planning has to consider project

impacts on all parts of the value chain over the long run.

The absence of a coordinated planning mechanism has led to redundant and surplus capacities, creating

bottlenecks in the grid system, and placing infrastructure where there is limited load (and vice versa). As

a result, electricity consumption averages around 4,000 MW for an estimated national load demand

estimated to be as high as 11,000 MW.16

Figure 3 below offers an approximation of the current idle capacity, under the condition of no technical

or operational losses, from the geographic misplacement of infrastructure resources and unsolicited

power projects arising from absent integrated system planning mechanisms.

Figure 317: Approximation of Current Idle Infrastructure Capacity18

2.2.6 Value Chain Liquidity Impact

System Affordability – As noted and illustrated in the figure above, the presence of surplus capacities

has an adverse effect on system affordability. More specifically, surplus capacities have an adverse effect

on system affordability if they are considered as part of the asset base during tariff determination. In other

words, rate payers will be unfairly burdened if idle capacities are inadvertently included in the asset base.

Hence, the regulator should effectively distinguish between idle and utilized portions of power sector

assets and only account for utilized portions in the asset base during tariff determination.

Furthermore, system affordability may be adversely impacted if all PPAs signed by NBET are fully activated

because an activated PPA requires payment be made for available capacity regardless of whether or not

energy is delivered. Only five GENCOs currently receive payment for available capacity, three of which

have active gas supply agreements whereas the other two have a minimum guaranteed capacity payment.

The remaining GENCOs receive payments based on energy delivered.

16 NARUC Technical Assistance Project (2018), Transmission Expansion Plan (Fichtner), NERC Quarterly Reports,

and Year 1 NPSP Workplan (USAID). 17 NERC Quarterly Reports, NARUC Technical Assistance Project (2018), Transmission Expansion Plan (Fichtner),

and Year 1 NPSP Workplan (USAID). 18 Note: The installed capacity numbers in Figure 3 are estimates.


Efficient Tariff Determination – The lack of an integrated approach in reviewing and approving system

plans hinders the adequate recovery of system costs through an efficient tariff determination. In reference

to Market Rules 21.1.1 – Annual Load Projections Report, NERC is responsible for performing a tariff

affordability test to estimate the impact of new power procurements on tariffs. The absence of a cost-

reflective tariff is a key liquidity challenge in the Nigerian electricity market.

Costs Benefit Analysis – A long term system plan, with broad stakeholder participation, can ensure the

selection of the lowest cost and lowest risk investment plan in developing a policy based efficient power

sector. Conversely, the absence of a plan can lead to the pursuit of high cost and high-risk investment

plans, resulting in additional deadweight infrastructure in the sector. Deadweight infrastructure refers to

investments which add to the running costs of the power sector despite having only a negligible impact

on the overall service delivery.

2.2.7 Investment Monitoring Mechanism Impact

Without monitoring by NERC, there is no way to ensure that the implementation of investments is aligned

with approved expansion plans. Misaligned investments may result in an overinvestment or an

underinvestment in distribution grids that: (1) do not demand any further loads or are unwilling to pay for

additional electricity supply; or (2) in grids that demand further loads or are willing to pay for additional

electricity supply, respectively. Recent reports have demonstrated the presence of capacity mismatches,

especially between transmission and distribution networks.19 In other words, assuming approved

expansion plans have taken into consideration a cost-benefit analysis, monitoring ensures investments are

aligned to achieving a positive return on investments, thereby reducing liquidity risk.

2.2.8 Social and Environmental Impact

The lack of a sector plan, along with lax monitoring mechanisms, makes it difficult to assess the social and

environmental impacts of power sector infrastructure investments. In other words, a long-term plan can

help ensure power sector infrastructure investments meet social and environmental objectives set by

FGN.

19 NARUC Technical Assistance Project (2018)


3. LOAD DEMAND FORECASTING

3.1 OVERVIEW

There is no shared and consistent load projection estimate and approach among the key actors in the

Nigerian power sector. Load demand projections are a key input of power sector expansion plans. An

inaccurate load projection may result in an inadequate allocation of power sector resources which fails to

meet future load demand and results in unnecessary system costs through the presence of idle resources.

It is worth noting that given the current model of unsolicited power projects, load demand forecasts don’t

seem to play a crucial role in informing infrastructure investments.

The main challenge hindering Nigeria’s load demand forecasting mechanism is the lack of stakeholder

technical capacity. This provides NPSP with the opportunity to support NERC, TCN, DISCOs, and large

users with the development of load forecast templates and operational plans to address technical capacity

gaps.

The Grid Code and Distribution Code contain rules and regulations that govern the process of load

demand forecasting. A review of the TCN System Adequacy Report (2017) and the TCN Demand

Forecast Report (2017) reveals an independent load projection by TCN (forecasted by the Japan

International Cooperation Agency) without taking into consideration any input from DISCO load demand

forecasts.20 This current practice is not compliant with Grid Code 6.2.2 Long-term Demand Forecast and

the Market Rules. Like TCN, DISCOs use load projections without required reviews and approvals laid

out in the Market Rules.21 Figure 4 below illustrates the missing procedural steps required by the Market

Rules, Grid Code, and Distribution Code.

Figure 422: Load Forecast Process Gaps23

3.1.1 Grid Code

Grid Code 6.2 Long-term Demand Forecast specifies that a new 20-year demand forecast should be

published every three years, with annual updates, and identifies the factors that need to be taken into

20 TCN System Adequacy Report (2017) and TCN Demand Forecast Report (2017) 21 NARUC Technical Assistance Project (2018) 22 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,

Grid Code Chapter 2 - Planning, Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures,

and NARUC Technical Assistance Project (2018) 23 Note: TCN is currently the System Operator of the Nigerian power sector. Figure 4 does not capture all the

activities from Market Rules and other FGN laws and regulations such as the Grid Code and Distribution Code.


consideration when generating demand forecasts, respectively. This assessment does not seek to list all

existent procedural rules or identify all the procedural gaps with FGN rules. However, a cursory review

of TCN’s Demand Forecast Report (2017) yields a brief assessment on compliance gaps with the Grid

Code; please refer to Table 3 below.

Table 324: Current TCN Forecast Factors vs. Grid Code Forecast Factors25

The load demand forecast used in TCN’s system adequacy assessment is developed by JICA. JICA

forecasted both energy and peak demand on a nationwide and regional basis for the period of 2017 to

2027. In developing each forecast, JICA utilized three (low, average, and high) GDP growth scenarios. It

is worth noting that the transmission expansion plan drafted by Fichtner in December 2017 (refer to the

Transmission Expansion Planning Section), calculated a revised demand forecast using data from previous

JICA progress reports. More specifically, the transmission expansion plan by Fichtner consulted the

following previous demand forecasts in its own demand forecast calculation: 1) the 2015 JICA demand

forecast, 2) the 2012 TCN demand forecast, and 3) the 2009 Tractebel demand forecast.26

3.1.2 Distribution Code

Section 2.3 in Part 2 of the Distribution Code specifies that a 5-year demand forecast should be published

annually and identifies the factors (i.e., growth in population, energy sales per customer category, etc.)

which need to be taken into consideration when generating demand forecasts.27 DISCOs have not been

preparing these forecasts on an annual basis. Although this assessment does not seek to list all existent

procedural rules or identify all the procedural gaps with FGN rules, the table below yields a cursory

assessment of the load demand forecast approach submitted by each DISCO. Table 4 below illustrates

that DISCOs, for the majority, have no consistent formal approach to forecasting load demand.

24 TCN Demand Forecast Report (2017) and Grid Code 6.2.2 and 6.2.3 - Long-term Demand Forecast 25 Note: Table 3 above is meant to illustrate a discrepancy between current practices and regulations. It is not meant

to critique or offer an analysis on the robustness of the TCN report load demand forecast approach by JICA. If there

was a slight overlap with what was covered in the report and what is required from the Grid Code, it was marked

as present. 26 Transmission Expansion Plan (Fichtner) 27 Section 2.3 in Part 2 of the Distribution Code – Load Forecast


Table 428: Current DISCO Forecast Approach29


3.2.1 Power Exports Challenge

Most export requirements are agreement-based (i.e., the power requirements are fixed). Nonetheless, it

is crucial for NERC and the System Operator, TCN, to account for future potential export requirements

when ensuring future system reliability through long-term planning. Currently NERC has not received any

load forecasts or potential future requirements from any entity receiving exports as part of its current

review of load forecasts and expansion plans.

As a member of the West African Power Pool, Nigeria currently exports approximately 350 MW of

power to utilities in neighboring countries.30 Benin/Togo and Niger account for approximately 250 MW

and 100 MW of Nigerian exported power, respectively.31 Nigeria’s current export requirement accounts

for approximately nine percent of the power distributed to end users (approximately 4,000 MW).32

28 NARUC Technical Assistance Project (2018) 29 NARUC Technical Assistance Project (2018) carried out the analysis using completed submissions by DISCOs of

the general template provided by NERC. 30 TCN 31 Ibid 32 NERC Quarterly Reports


3.2.2 Accurate Load Forecasts Challenge

Limited technical capacity, along with ineffective data collection and database management systems at

DISCOs are a contributing factor to inaccurate forecast estimates. The lack of a scalable software or

formal shared model template to be used at DISCOs for forecasting can hinder accuracy and most of all

make the review process more difficult for the commission.

It is important to note that large users, such as industrial customers, also have a role in providing accurate

forecasts. According to Section 2.3.4 in Part 2 of the Distribution Code, large users should provide

DISCOs with their 5-year energy demand forecasts on an annual basis.33

33 Section 2.3 in Part 2 of the Distribution Code – Load Forecast

NPSP can help TCN and NERC develop commercial frameworks around the

purchase of power by utilities in West African countries. NPSP can support the

inclusion of export demands in long-term planning and the development of PPAs

between Nigerian GENCOs and West African utilities.

To improve load forecast accuracy, NPSP can provide support to the following

power sector stakeholders:

1. NERC: NPSP can support the development of load forecast templates and

methodology guidelines, in addition to supporting the improvement of load

forecast review mechanisms.

2. DISCOs and users with large connections (e.g., industrial companies): NPSP

can address capacity gaps by implementing stakeholder development

programs.

3. TCN: NPSP can support with load forecast data retrieval, analysis,

processing, and incorporating the processed data into scheduling and

dispatch functions.


4. DISTRIBUTION EXPANSION PLANNING

4.1 OVERVIEW

Until now, distribution expansion was carried out in isolation by the DISCOs and without the presence

of robust and approved distribution expansion plans. Carrying out distribution expansion investments in

isolation from the power sector value chain has resulted in the placement of distribution capacity

infrastructure that remains idle for prolonged periods of time due to not accounting for the future

availability of generation resources and transmission capacity at certain connection points. This previous

practice is not compliant with the Market Rules and leading practices. It is worth noting that currently

NERC received five-year distribution expansion plan templates from DISCOs for review, along with

associated investment plans and single line drawings.

The main challenge hindering Nigeria’s distribution expansion planning mechanism is the limited technical

capacity of DISCOs. This provides NPSP with the opportunity to support DISCOs with the development

and implementation of operational plans to address technical capacity gaps.

Figure 5 below illustrates the procedural steps required by the Market Rules with respect to distribution

system planning. Activities deemed to be critical for an integrated approach to planning are highlighted.

Figure 534: Distribution Expansion Plan Market Rules Process35

Given that the Market Rules are written in the context of the transitional and medium-term stages of

NESI, the activities of NBET are not highlighted as critical integration activities. NBET is best described as

an intermediary between GENCOs and DISCOs in the process of power procurement. NBET engages in

34 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage,

Grid Code Chapter 2 - Planning, and Section 2 in Part 2 of the Distribution Code – Distribution Planning Procedures 35 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the

Nigerian power sector. Figure 5 does not capture all the activities from Market Rules and other FGN laws and

regulations such as the Distribution Code.


active trading of bulk power as a buyer of power from GENCOs and a seller of purchased power to

DISCOs.

4.1.1 Distribution Code

Another FGN law and/or regulation governing the process and requirements of the Distribution

Expansion plan is the Distribution Code. The specific rules that govern the requirements and approach to

DISCO expansion planning are in Section 2 under Part 2 of the Distribution Code. Other than their

current NERC submission, DISCOs have not been preparing expansion plans on a periodic basis. Although

this assessment does not seek to list all existent procedural rules or identify all the procedural gaps with

FGN rules, a cursory review of the NARUC Technical Assistance Project (2018) inception report analysis

yields a brief assessment on compliance gaps with the Distribution Code; please refer to Table 5 below.

Table 536: DISCO Expansion Plan vs. Required Distribution Code Attributes37

Most DISCOs do not seem to be engaging in any form of formal study or analysis in formulating their

expansion plan. Furthermore, projected investment costs supplied by the DISCOs were mostly not

supported by the required planning and system studies. As a reminder, it is prudent to note that most

36 NARUC Technical Assistance Project (2018) and Section 2 in Part 2 of the Distribution Code – Distribution

Planning Procedures (2.1.3, 2.4, and 2.5) 37 Note: Table 5 illustrates a discrepancy between current practices and regulations. It is not meant to critique or

offer an analysis on the robustness of the approach for each DISCO. Also, the required demand forecast portion of

expansion plans is covered in the Load Demand Forecasting subsection above. If there was a slight overlap with what

was covered in the report and what is required from the Distribution Code, it was marked as present.


expansion plans require accurate load forecasts; refer to the Load Demand Forecasting section above for

a brief discussion on the current state of DISCO load demand forecasting.

Table 6 below offers more detail on the Distribution Code (Part 2) sections that govern the planning

process and requirements of DISCOs in formulating expansion plans.

Table 6: Distribution Code (Part 2) Sections Governing DISCO Planning

Section Activity Required Components

2.1.3

Annual 5-year

Distribution

Plan

projections

1. Energy and demand forecasts

2. Distribution feeder routing and sizing

3. Distribution reactive power compensation plan

4. Distribution losses reduction plan

5. Other distribution reinforcement plans

6. A technical and economic analysis to justify the 5-year distribution expansion

plan

2.4

Planning

process studies

and analysis

objectives

1. Evaluate the requirement of distribution system reinforcement projects

2. Identify corrective measures to eliminate the deficiencies in the system

3. Assess the impact on the system due to the load forecast or any proposed

equipment change

4. Determine optimum patterns for feeder development taking into account

existing or future substations

5. Develop optimum reactive power compensation programs

6. Develop an optimum feeder configuration and switching controls

7. Determine the cost effectiveness of loss reduction measures without

compromising security standards

2.5 Studies and

analysis

1. Voltage drop studies

2. Short circuit studies

3. Three-phase short-circuit studies

4. System losses studies

5. Distribution reliability studies


4.2.1 Network Expansion Challenge

DISCOs lack the necessary capital expenditure funds to expand their networks because of the difficulty

to secure financing, the lack of a cost reflective tariff, and the possible inadequate capital expenditure

allocations in recent MYTO adjustments. As a result, the feasibility of implementing any type of distribution

expansion plan is low.

4.2.2 DISCO Capacity Challenge

The infrequent formulation of distribution expansion plans utilizing methodologies set by FGN rules and

leading practices may be attributed to the DISCO’s current capacity and technical capabilities. DISCOs

lack any effective data collection methods, database management systems, software, and formal shared

model templates to adequately conduct the required studies and analysis necessary in forming expansion

plans.


4.2.3 Power Procurement and Distribution Expansion Impact

Not taking into consideration the current and future state of generation adequacy, along with integrated

transmission and generation capacity plans, results in inadequate distribution expansion investments. In

other words, not accounting for the future availability of generation resources to supply demanded loads

can result in the placement of distribution capacity infrastructure that remains idle for prolonged periods

of time.

To improve distribution expansion, NPSP can support DISCOs to address capacity

gaps and improve their ability to conduct effective distribution expansion planning.


5. TRANSMISSION EXPANSION PLANNING

5.1 OVERVIEW

One of the main purposes of the Transmission Expansion Plan is to ensure future load and generation

connections can be handled by the transmission system. If not, then TCN is responsible for identifying and

planning for required expansions. Until recently, Transmission Expansion plans were carried out in

isolation from the power sector value chain. In combination with other factors, this has contributed to an

inadequate transmission evacuation capacity of approximately 7,000 MW, despite an installed transmission

transformation capacity of approximately 11,000 MW, that fails to meet the national load demand

(approximately 11,000 MW) and available output from GENCOs (approximately 7,500 MW).38 This

previous practice is not compliant with the Market Rules and leading practices.

The main challenge hindering Nigeria’s transmission expansion planning mechanism is the limited technical

capacity of TCN. This provides NPSP with the opportunity to support TCN with the development and

implementation of operational plans to address technical capacity gaps.39

Figure 6 below illustrates the procedural steps required by the Market Rules with respect to transmission

system planning. Activities deemed to be critical for an integrated approach to planning are highlighted.

Figure 640: Transmission Expansion Plan Process41

It is worth noting that TCN, in conflict with FGN rules and regulations, does not release technical reports

on electricity system adequacy annually, which are required inputs to formulating the Transmission

38 NARUC Technical Assistance Project (2018) and Year 1 NPSP Workplan (USAID) 39 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the

Nigerian power sector. 40 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and

Grid Code Chapter 2 - Planning 41 Note: TCN is currently the System Operator, Market Operator, and the Transmission Service Provider of the


regulations such as the Grid Code.


Expansion Plan. Table 7 below offers a brief overview of the current approach and methodologies utilized

for the relevant system adequacy reports.

Table 7: System Adequacy Reports Current Methodology Overview42

Part Report Objective / Metric Performance Indices / Methodology

Inputs

One

Generation

Adequacy Report -

Retrospective

(2015)

Analyzes the capability of

generating stations to supply

load and provide the

required ancillary services

• Generation capacity before constraints

• Energy not supplied

• Utilization of electrical energy

• Remaining capacity margin

• Frequency regulation

• Voltage regulation (Currently unknown data)

• Black start capability

• System collapses

Two

Transmission

Adequacy Report -

Retrospective

(2015)

Analyzes the capability of the

transmission system to

transmit power reliably from

GENCOs to DISCOs

• Transmission line reliability (failure rate,

outage frequency, interruption duration,

etc.)

• Transformer reliability (failure rate,

availability, and average interruption

duration)

• Transmission constraints

• Voltage regulation

• Loss of transmission system

• Load management

Three Demand Forecast

Report Please refer to the Load Demand Forecasting section above

Four

Generation

Adequacy Outlook

(2017 – 2027)

Analyzes generation

adequacy (10yr outlook)

through energy and capacity

margins under different

scenarios (e.g., low, base, and

high case)

• Demand forecast

• Planned generation expansion

• Technical availability of power plants

• Constraints of primary energy (gas and

water)

Five

Transmission

Adequacy Outlook

(2017 – 2027)

Analyzes transmission

adequacy (10yr outlook)

using DC model of power

system, in addition to

determining 330kv and 132kv

networks separately

• Ongoing transmission projects

• Ongoing generation projects

• Transmission information (topology, thermal

capability, etc.)

• Maximum short-circuit levels

Currently, the NPSP team is aware of only one recent Transmission Expansion Plan, the December 2017

plan drafted by Fichtner. The Transmission Expansion Plan (Fichtner) covers the period 2020 to 2037

using TCN’s annual technical reports, up to the year 2015, as its main input. Figure 7 below offers a brief

overview of the components and approach adopted in the plan.

42 TCN System Adequacy Reports (2017)


Figure 7: Transmission Expansion Plan (Fichtner) Overview43

5.1.1 Grid Code

The specific rules that govern the requirements and approach to transmission expansion planning are in

Grid Code Chapter 2 Planning.

Grid Code Section 7 Expansion Planning discusses the timelines, user involvement, analysis, components,

and process of the transmission expansion planning approach. It is worth noting that TCN has not been

preparing expansion plans on a periodic basis in accordance to the stipulated regulations. More specifically,

Section 7.2 of the Grid Code clearly lists out the required process and components/analysis for drafting

the long-term expansion plan report. Grid Code Section 7.2.4 mandates the Transmission Service Provider

with the responsibility to identify expansion alternatives, with input from relevant stakeholders, that

address the combination of: (1) long-term demand forecasts; (2) refurbishment needs; and (3) current

transmission performance. As per Grid Code Section 7.2.5 the evaluation of alternatives should be

performed by taking into consideration the following studies: (1) a load flow analysis; (2) fault level

calculations; (3) stability studies; (4) reliability studies; and (5) a financial analysis.

Grid Code Section 7.2.7 Long-term Expansion Plan Report defines the following sections that need to be

included in the long-term expansion plan report:

1. Long-term demand forecast;

2. Long-term generation adequacy forecast;

3. Long-term transmission adequacy forecast;

4. Long-term zonal supply and demand margin;

5. Long-term statutory outage plan for transmission infrastructure;

6. Long-term refurbishment plan;

7. Alternatives (identification and analysis);

8. Capital investment program; and

9. Financial motivation.

In addition, Sections 7.3 and 8 of the Grid Code pertain to guidelines for user involvement and the data

requirements for long-term planning, respectively. More specifically Section 8 along with Appendix 5

through Appendix 7 clearly list out all the user information, DISCO and GENCO, required.

43 Transmission Expansion Plan (Fichtner)


Figure 8 below illustrates an overview of the required Grid Code process in generating Transmission

Expansion Plans. Activities deemed to be critical for an integrated approach to planning are highlighted.

Figure 844: Transmission Expansion Plan Grid Code Process45


5.2.1 TCN Capacity Challenge

In line with the Stakeholder Capacity Challenge raised in the System Planning section, the infrequent

submission and/or revision of expansion plans, along with system adequacy reports, utilizing

methodologies set by FGN rules (e.g., Market Rules 21.2 Generation Adequacy Report, Grid Code 7.2

Long-term Expansion Plan, etc.) and leading practices may be attributed to TCN’s current capacity and

technical capabilities. Relative to the other stakeholders of the power section value chain, TCN has human

resources that are technically capable and has software tools that are implemented. However, TCN’s

capacity is constrained by an inadequate information management system, inadequate workflow processes,

and their reliance on receiving accurate inputs from DISCOs and GENCOs.

5.2.2 Transmission Expansion Impact

The lack of an integrated approach to planning, inclusive to estimating load forecasts without DISCO

inputs, has led to the misalignment of transmission capacity with generation resources and load

requirements at certain connections. Current transmission evacuation capacity (approximately 7,000

MW) is less than the national load demand (approximately 11,000 MW) and available output from

GENCOs (approximately 7,500 MW), even though the installed transmission transformation capacity is

11,000 MW.46

44 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and



regulations such as the Grid Code. 46 NARUC Technical Assistance Project (2018), NERC Quarterly Reports, Transmission Expansion Plan (Fichtner),

and Year 1 NPSP Workplan (USAID)


6. GENERATION EXPANSION PLANNING

6.1 OVERVIEW

Investments in generation infrastructure are carried out with no generation expansion plan and in isolation

from any inputs from other stakeholders of the Nigerian power sector. The absence of a generation

expansion plan along with any present explicit mechanism for generation expansion planning, implies no

previous energy resource plan (e.g., gas transmission expansion plans) integrated with decisions on

generation investments. Unsolicited generation projects are often taken forward for FGN approval

without consideration of grid capacity and energy resource availability. This is clearly depicted by an

available generation capacity of approximately 7,500 MW, despite an installed gross power generation

capacity of 13,500 MW.47

The main challenge hindering Nigeria’s generation expansion planning mechanism is the lack of an adequate

mechanism for generation expansion planning and GENCO feedback. This provides NPSP with the

opportunity to support the development of a mechanism for the formation of a robust generation

expansion plan that is effectively communicated to GENCOs and considers energy resource availability

and inputs from relevant stakeholders.

Generation Expansion Planning helps to:

1. Ensure the presence of enough generation capacity to efficiently supply current and future

load demand;

2. Ensure system reliability with the presence of reserve generation capacity; and

3. Properly anticipate and address maintenance needs, outage occurrences, development needs

(financing, licenses, etc.), and energy resource supply needs such as the availability and/or price

of gas, coal, or water.

Currently, this assessment is aware of only one recent completed generation expansion plan.48 TCN, along

with Fichtner, in 2017 identified a generation development plan for consideration in the formulation of

the Transmission Expansion Plan and network calculations. The plan is referenced to be in Annex 6.1 of

the Transmission Expansion Plan (Fichtner).

According to the Transmission Expansion Plan (Fichtner), Annex 6.1 identifies a generation setup for the

modernization of generating units, implementation of new generating units at existing sites, and

implementation of complete new power plants with the aim to supply potential load demand. The

generation plan has been finalized and revised by TCN at the end of August 2017 considering existing

plants and plant candidates. To bolster the proposition of building certain types of plants at certain sites,

TCN initiated the development of a gas transmission system expansion plan as well. The expansion plan

proposes new gas transmission pipelines to supply the northern and central regions of Nigeria. Figure 9

below is a schematic from TCN, retrieved from the Transmission Expansion Plan (Fichtner), showing the

proposed and ongoing gas transmission expansion plan with some locations for proposed new gas fired

power plants.

47 NARUC Technical Assistance Project (2018) and Year 1 NPSP Workplan (USAID) 48 As noted earlier, JICA is currently in the process of conducting a comprehensive power sector Master Plan which

includes an optimal power generation master plan considering constraints in energy supply. Also, it is worth noting

that according to NPSP meeting notes with JICA (September 3, 2018), the JICA plan incorporates the Fichtner plan.


Figure 9: Existing and Proposed Gas Transmission Infrastructure49

It is worth noting that a comment in the Transmission Expansion Plan (Fichtner) stated that the generation

plan in Annex 6.1 has made rather optimistic assumptions with respect to the implementation of candidate

power plant projects.

Furthermore, the generation plan proposed in Annex 6.1 of the Transmission Expansion Plan (Fichtner)

has not been subject to a thorough generation adequacy and feasibility assessment. The only present

generation adequacy report this assessment is aware of is the TCN Generation Adequacy Report: Outlook for

2017 – 2027. Although there is a present generation adequacy report, by the time the report was

prepared there was no Generation Expansion Plan available. As a result, the report only considered

planned power projects.

None of FGN laws and regulations clearly specify any criteria or processes to be undertaken in the

formulation of a generation system plan, along with an energy resource plan. The System Operator is

mandated to undertake system planning for generation; Market Rules 9.1.2 System Operation. However,

the Market Rules only go as far as mandating the System Operator with the responsibility to select the

locations for new generation capacity; Market Rules 21.1.6 Annual Load Projections Report. Figure 10

below illustrates the procedural steps required by the Market Rules with respect to generation location

selection and new power procurement. Activities deemed to be critical for an integrated approach are

highlighted.

49 Transmission Expansion Plan (Fichtner)


Figure 1050: Generation Expansion Plan Process51

As illustrated by the figure above, the System Operator is mandated with reviewing the Transmission

Expansion Plan, taking into consideration reserve requirements, and identifying the best location for

additional generation; Market Rules 21.1.6 Annual Load Projections Report. Although not stated above,

the output of the load demand and generation plan is reported in the Load Projection Report. According

to Market Rule 21.2.1 Generation Adequacy Report, after the plan is formulated, the Market Operator is

mandated in evaluating the adequacy of the generation plan by preparing the Generation Adequacy Report.

Afterwards, based on the Generation Adequacy Report, NERC will decide on the quantity to be traded

in new contracts and will notify NBET of the quantity authorized for new power procurement by each

DISCO. NBET then procures the required additional capacity on behalf of the DISCOs, but with their

consent on the final terms of the PPAs.

It is crucial to note that a Generation Adequacy Report is not a substitute for a Generation Expansion

Plan. Furthermore, as noted above, the generation adequacy outlook report published by TCN is not

relevant since it should be testing the adequacy of a proposed generation plan to ensure the plan satisfies

forecasted load demand reliably.

In addition, there is no identified planning mechanism to ensure generation plans, inclusive to energy

resource plans, receive the relevant inputs from gas suppliers, the Nigerian Meteorological Agency, and

the Nigeria Hydrological Services Agency.

50 Market Rules Part 5 - Contracts, Generation Adequacy and Power Procurement during the Transitional Stage and



regulations such as the Grid Code.


6.1.1 Interim Provision

As mentioned in the System Planning subsection above, NERC has in place an interim provision that

overrides the requirements on the preparation of the Load Projection Report; Market Rules 21.1.7 Annual

Load Projections Report. The current interim provision, titled Regulations for the Procurement of Generation

Capacity 2014, sets a standard in which the System Operator, in lieu of the Load Projection Report, will

only prepare an annual report assessing system capacity needs and constraints for a five-year period ahead.

The interim report lists out, but not limited to, the following components to be considered in the 5-year

report: (1) projected demand; (2) recommended injection points for generation capacity; (3) current and

projected natural gas and other fuel supply capabilities; and (4) projected transmission grid system

capabilities. The interim provision goes on to stipulate guidelines on the process of solicitation and

procurement for new generation capacity.


6.2.1 Guideline and Coordination Challenge

Although Market Rules 9.1.2 System Operation assigns the responsibility of generation system planning to

the System Operator, it falls short in providing details on how to conduct the planning exercise and which

stakeholders to coordinate with. Furthermore, the Grid Code does not describe any responsibility or

process with respect to generation system planning assigned to the System Operator.

6.2.2 Generation Expansion Planning Challenge

Current and potential plant developments disclosed by GENCOs and power system users are taken into

consideration when planning for generation capacity expansion. However, a challenge lies in whether to

fully account for the MW produced by generation projects. A generation developer needs to reach various

agreements with FGN (e.g., PPAs) and regulatory entities such as NERC (e.g., license acquisitions) to

implement their generation projects. The process of reaching agreements and obtaining licenses may delay

the start date to which the potential project may provide available generation capacity. It may even lead

to the cancellation of projects or the development of plants that sit idle. Also, there are uncertainties with

respect to the implementation of the generation expansion program due to the large investment

requirements and financing needs. The rehabilitation and replacement of selected existing generation

capacity in the expansion plan will also require large investments. It is important to note that non-payment

for generation capacity delivered or made available creates a disincentive for GENCOs to maintain existing

capacity and/or increase capacity through plant refurbishments.

6.2.3 GENCO Feedback Mechanism Challenge

A major component of generation planning is the feedback mechanism used by System Operators to

communicate to GENCOs for the supply of future capacity at certain locations. Although the current

Transmission Expansion Plan (Fichtner) has a Generation Expansion Plan located in Annex 6.1, there is no

clear feedback mechanism to GENCOs or power sector users in the installation or modification of

generating units at certain locations. The assessment noted a possible feedback mechanism stipulated in

Grid Code Section 7.3.3 Plant Modification, however it should be subject to more clarification.

Building on the response to the Planning Challenge above, NPSP can develop a

mechanism to ensure both generation and energy resource plans receive the relevant

inputs from gas suppliers, the Nigerian Meteorological Agency, and the Nigeria

Hydrological Services Agency.


6.2.4 Energy Resource Planning Challenge

Although the presence of an energy resource plan can help ensure fuel supply for power generation, it is

subject to external constraints beyond the control of planning. Like the Generation Expansion Planning

Challenge noted above, the feasibility of implementing the energy resource plan is low because of the large

investment requirements and financing needs. For example, with respect to gas resource supply, the cost

of gas exploration, treatment facilities, and supply systems is high. In addition, the energy resource plan

cannot circumvent market forces (i.e., devaluation of the Naira relative to U.S. dollars) from incentivizing

gas export by producers. Furthermore, there is little or no incentive to maintain existing gas pipelines or

ensure security of supply in the absence of activated gas supply agreements and persistent poor payment

for gas by GENCOs.

6.2.5 Generation Expansion Planning Impact

The absence of a Generation Expansion Plan makes it difficult to ensure enough generation capacity to

supply current and future demand loads, as well as reserve capacity for system reliability. Ignoring

transmission constraints, the total generation available of approximately 7,500 MW (~55 percent of

installed capacity) currently falls short from the estimated national load demand of approximately 11,000

MW.52

In addition, many generating units, specifically gas turbine units, have reached or are approaching the end

of their operational lifetime. These old units are susceptible to breakdowns and are causing more planned

maintenance outages. The need for an expansion plan is crucial to address existing plant refurbishments

or replacements. It is anticipated that a replacement need of up to 3000 MW of existing generation

capacity is expected within the next five to ten years.53

6.2.6 Energy Resource Planning Impact

Generation output is dependent on, but not limited to, the following: (1) the availability of generation

units; (2) gas supply for thermal power plants; and (3) water inflow for hydropower plants. The absence

of an adequate resource plan component of a Generation Expansion Plan is partially responsible for non-

operational generating units due to gas transmission constraints (e.g., pipeline size). It is fair to note that

in some cases gas supply is constrained and/or interrupted by the sabotage of the gas pipeline system. The

impact of gas constraints in 2016 rendered approximately 3,700 MW (~30 percent of installed capacity)

of generation capacity unavailable.54 An expansion plan can facilitate more detailed requirements for gas

exploration, gas treatment facilities, and gas supply systems (e.g., pipelines) to ensure the availability of

thermal power plant generation capacity.

52 NARUC Technical Assistance Project (2018) and Transmission Expansion Plan (Fichtner) 53 Transmission Expansion Plan (Fichtner) 54 Ibid

Building on the response to the Planning Challenge above, NPSP, in addition, could

assist the System Operator in facilitating planning workshops to communicate

generation expansion plans with stakeholders such as GENCOs, gas suppliers, NBET,

and other relevant public and private entities.


7. CONCLUSION

The absence of an integrated approach to long-term system planning has resulted in an unreliable power

grid with misplaced infrastructure investments. Adopting an integrated planning approach can ensure

resources are allocated efficiently to reliably meet future load requirements. This assessment builds on

the USAID funded technical assistance project by NARUC to develop NERC’s capacity to evaluate system

planning and will guide future NPSP reform efforts, considering how stakeholder buy-in will make some

interventions more feasible than others. Based on the findings of this report, NPSP identifies the following

five priority short-term actions, subject to USAID approval:

1. Support NERC in finalizing a planning framework originating from the NARUC Technical

Assistance Project (2018) consultant and NERC;

2. Support NERC and the System Operator to organize an industry workshop with all system

participants to effectively communicate the steps towards effective planning;

3. Identify and form operational plans to address capacity gaps afflicting planning stakeholders;

4. Support the audit and verification of power sector infrastructure assets; and

5. Facilitate planning workshops communicating generation expansion plans with stakeholders such

as GENCOs, gas suppliers, NBET, and other relevant public and private entities.

NPSP will take into account other ongoing donor activities in order to mitigate any overlap and identify

any synergistic opportunities. NPSP is well aware that intervention activities may include a component of

data consolidation to account for the ongoing planning efforts and studies, such as the JICA Power Sector

Master Plan Study. NPSP acknowledges that future interventions face the challenges of: (1) a potential

change in leadership within FGN following the elections; and (2) the lack of stakeholder incentives to

engage in reform arising from inactive agreements and liquidity issues, among others.

nigeria power sector program long-term …

Documents